NOTE 9 - RETAIL RATES AND REGULATORY ACCOUNTING

Retail Rates Our retail rates are approved by the PSB after considering the recommendations of Vermont's consumer advocate, the DPS. Fair regulatory treatment is fundamental to maintaining our financial stability. Rates must be set at levels to recover costs, including a market rate of return to equity and debt holders, in order to attract capital.

Alternative Regulation: On September 30, 2008, the PSB issued an order approving our alternative regulation plan. The plan became effective on November 1, 2008. It was scheduled to expire on December 31, 2011. The plan allows for quarterly PCAM adjustments to reflect changes in power supply and transmission-by-others costs and annual base rate adjustments to reflect changes in operating costs; and an annual ESAM adjustment to reflect changes, within predetermined limits, from the allowed earnings level. Under the plan, the allowed return on equity is adjusted annually to reflect one-half of the change in the average yield on the 10-year Treasury note as measured over the last 20 trading days prior to October 15 of each year. The ESAM provides for the return on equity of the regulated portion of our business to fall between 75 basis points above or below the allowed return on equity before any adjustment is made. If the actual return on equity of the regulated portion of our business exceeds 75 basis points above the allowed return, the excess amount is returned to customers in a future period. If the actual return on equity of our regulated business falls between 75 and 125 basis points below the allowed return on equity, the shortfall is shared equally between shareholders and customers. Any earnings shortfall in excess of 125 basis points below the allowed return on equity is fully recovered from customers. As such, the minimum return for our regulated business is 100 basis points below the allowed return. These adjustments are made at the end of each fiscal year.

The ESAM also provides for an exogenous effects provision. Under this provision,we are allowed to defer the unexpected impact if in excess of $0.6 million, of changes in GAAP, tax laws, FERC or ISO-NE rules and major unplanned operation, maintenance costs, such as those due to major storms and other factors including loss of load not due to variations in heating and cooling temperatures. In 2011, we deferred $7.5 million of costs related to Tropical Storm Irene and legislative and tax law changes. We plan to file with the PSB by May 1, 2012, for recovery of these costs commencing on July 1, 2012 as provided by our alternative regulation plan.

By order dated March 3, 2011, the PSB approved amendments to the alternative regulation plan that: 1) extend its duration until December 31, 2013; 2) alter the methodology for implementing the non-power cost cap contained in the plan; 3) reset our allowed ROE to 9.45 percent; and 4) remove provisions no longer applicable to the provision of our services.

Using the methodology specified in our alternative regulation plan, we estimated our 2011 return on equity from the regulated portion of our business to be approximately 9.09 percent. We are required to file this calculation with the PSB by May 1, 2012. No ESAM adjustment was required since this return was within 75 basis points of our 2011 allowed return on equity of 9.45 percent.

The PCAM adjustment for the fourth quarter of 2011 was an over-collection of $0.3 million and was recorded as a current liability. This over-collection will be returned to customers over the three months ending June 30, 2012. We filed a PCAM report with the PSB identifying this over-collection. The PSB has not yet acted on this filing.

The PCAM adjustment for the third quarter of 2011 was an under-collection of $0.3 million and was recorded as a current asset. This under-collection will be collected from customers over the three months ending March 31, 2012. We filed a PCAM report with the PSB identifying this under-collection. The DPS recommended the PCAM report be approved as filed and the PSB accepted the DPS recommendation and approved the filing.

The PCAM adjustment for the first quarter of 2011 was an over-collection of $1 million and for the second quarter of 2011 was an over-collection of $0.8 million. These amounts were recorded as current liabilities and were returned to customers over the three months ending September 30, 2011 for first quarter and ending December 31, 2011 for the second quarter.

On November 1, 2011, we submitted a base rate filing for the rate year commencing January 1, 2012, as required by our alternative regulation plan. The filing proposes an increase in base rates of $15.8 million or a 4.78 percent increase in retail rates, reflecting an allowed ROE of 9.17 percent. Under our alternative regulation plan, the annual change in the non-power costs, as reflected in our base rate filing, is limited to any increase in the U.S. Consumer Price Index for the northeast, less a productivity adjustment that varies based upon the results of a comparison of certain cost metrics of the company with those of a benchmark group of U.S. electric utilities. For the 2012 rate year, the productivity adjustment was 0.95 percent. The non-power costs associated with the implementation of our Asset Management Plan and our CVPS SmartPower® project are excluded from the non-power cost cap. Our 2012 forecasted non-power costs did not exceed the non-power cost cap. On December 28, 2011, we received approval from the PSB and the 4.78 rate increase went into effect January 1, 2012.

CVPS SmartPower® On October 27, 2009, the DOE announced that Vermont's electric utilities will receive $69 million in federal stimulus funds to deploy advanced metering, new customer service enhancements and grid automation.

On April 15, 2010, we signed an agreement with the DOE for our portion of the Smart Grid stimulus grant and project and the agreement became effective April 19, 2010. The agreement includes provisions for funding and other requirements. We are allowed to receive reimbursement of 50 percent of our total eligible project costs incurred since August 6, 2009, up to $31 million. From the inception of the project through December 31, 2011, we have incurred $13.8 million of costs, of which $7.7 million were operating expenses and $6.1 million were capital expenditures. In 2011, we have incurred $9.2 million of costs, of which $5.3 million were operating expenses and $3.9 million were capital expenditures.

We have submitted requests for reimbursement of $6.2 million and have received $5 million to date, of which $3.3 million was received in 2011.

On July 19, 2011, we entered into a contract for the communications infrastructure in support of our advanced metering project. The overall contract is approximately $6.2 million for which we are jointly and severally liable with another party. Our share of the contract cost is approximately $3.9 million. The contract calls for a $1.9 million initial payment with remaining payments for certain milestones to be made over a two-year period. In August 2011, we made the initial payment of $1.9 million and received 50 percent reimbursement from the DOE.

Pending Merger with Gaz Métro Also, see Note 1 - Business Organization, Pending Merger with Gaz Métro, Regulatory approvals.

Regulatory Accounting Under the FASB's guidance for regulated operations, we account for certain transactions in accordance with permitted regulatory treatment whereby regulators may permit incurred costs, typically treated as expenses by unregulated entities, to be deferred and expensed in future periods when recovered through future revenues. In the event that we no longer meet the criteria under accounting for regulated operations and there is not a rate mechanism to recover these costs, we would be required to write off $11.5 million of regulatory assets (total regulatory assets of $49 million less pension and postretirement medical costs of $37.5 million), $13.8 million of other deferred charges - regulatory and $4.1 million of other deferred credits - regulatory. This would result in a total charge to operations of $21.2 million on a pre-tax basis as of December 31, 2011. We would be required to record pre-tax pension and postretirement costs of $37.3 million to Accumulated Other Comprehensive Loss and $0.2 million to Retained Earnings as reductions to stockholders' equity. We would also be required to determine any potential impairment to the carrying costs of deregulated plant. Regulatory assets, certain other deferred charges and other deferred credits are shown in the table below (dollars in thousands).

	December 31, 2011		December 31, 2010
Regulatory Assets - Long-term Portion:
Pension and postretirement medical costs	$	37,300	$	27,959
Nuclear plant dismantling costs		3,827		5,383
Income taxes		4,722		4,480
Asset retirement obligations (a) (d)		426		487
Other (b) (d)		106		243
Total Regulatory Assets -Long-term Portion		46,381		38,552
Regulatory Assets - Current Portion:
Pension and postretirement medical costs (c) (d)		235		0
Nuclear refueling outage costs - Millstone Unit #3 (c) (d)		805		486
Nuclear plant dismantling costs (c) (d)		1,433		1,438
Asset retirement obligations and other (c) (d)		132		0
Total Regulatory Assets - Current Portion		2,605		1,924
Total Regulatory Assets	$	48,986	$	40,476


Other Deferred Charges - Regulatory - Long-term Portion:
ESAM deferred costs (b) (d)	$	3,759	$	2,079
Environmental (d)		108		0
FERC relicensing		609		0
Other (d)		147		181
Total Other Deferred Charges - Regulatory - Long-term Portion		4,623		2,260
Other Deferred Charges - Regulatory - Current Portion:
Unrealized loss on power-related derivatives (c)		4,940		0
ESAM deferred costs (c) (d)		3,759		2,078
Other (c) (d)		503		0
Total Other Deferred Charges - Regulatory - Current Portion		9,202		2,078
Total Other Deferred Charges - Regulatory	$	13,825	$	4,338

Other Deferred Credits - Regulatory - Long-term Portion:
Asset retirement obligation - Millstone Unit #3	$	3,060	$	3,009
CVPS SmartPower® grant reimbursements		0		222
Other (c) (d)		21		655
Total Other Deferred Credits - Regulatory - Long-term Portion:		3,081		3,886
Other Deferred Credits - Regulatory - Current Portion:
CVPS SmartPower® grant reimbursements (c) (d)		222		958
Other (c) (d)		825		150
Total Other Deferred Credits - Regulatory - Current Portion		1,047		1,108
Total Other Deferred Credits - Regulatory	$	4,128	$	4,994

(a) Remaining recovery period is 14 years
(b) Remaining recovery period is two years
(c) Remaining recovery period is one year
(d) Currently earning a return

The regulatory assets included in the table above are being recovered in retail rates and are supported by written rate orders. The recovery period for regulatory assets varies based on the nature of the costs. Other deferred charges – regulatory are supported by PSB-approved accounting orders or approved cost recovery methodologies, allowing cost deferral until recovery in a future rate proceeding. Most items listed in other deferred credits - regulatory are being amortized for periods ranging from two to three years. Pursuant to PSB-approved rate orders, when a regulatory asset or liability is fully amortized, the corresponding rate revenue shall be booked as a reverse amortization in an opposing regulatory liability or asset account.

Regulatory assets for pension and postretirement medical costs are discussed in Note 12 - Pension and Postretirement Medical Benefits. Regulatory assets for nuclear plant dismantling costs are related to our equity interests in Maine Yankee, Connecticut Yankee and Yankee Atomic which are described in Note 4 - Investments in Affiliates. Power-related derivatives are discussed in more detail in Note 6 - Fair Value.